Method of Sealing an Annular Space in a Wellbore

ABSTRACT

A method is provided of sealing an annular space between an expandable tubular element arranged in a wellbore and a wall surrounding the expandable tubular element. A pressure difference occurs between a first location in the annular space and a second location in the annular space axially spaced from the first location. The method comprises:
         installing the tubular element in the wellbore;   locating a body of fluid in the annular space between the first and second locations, the fluid having a yield strength selected such that the pressure difference is insufficient to induce axial flow of the body of fluid in the annular space after radial expansion of the tubular element; and   radially expanding the tubular element.

The present invention relates to a method of sealing an annular space formed between an expandable tubular element arranged in a wellbore and a wall surrounding the expandable tubular element, whereby a pressure difference occurs between a first location in the annular space and a second location in the annular space axially spaced from the first location.

Wellbores for the production of hydrocarbon fluid are conventionally provided with one or more casings to provide stability to the wellbore wall, and to provide zonal isolation between different earth formation layers. Generally several casings are set at different depth, in a nested arrangement whereby the diameter of each (subsequent) casing is smaller than the diameter of the previous casing in order to allow lowering of the casing through the previous casing. The annular space between each casing and the wellbore wall is filled with cement to provide annular sealing and to support the casing in the wellbore. In most applications such cement layer provides adequate sealing functionality as long as the annular space is not too narrow.

Recently it has become practice to radially expand casings in the wellbore. In an attractive method of installing expandable casings, each subsequent casing is lowered through the previous casing and then radially expanded to substantially the same diameter as the previous casing. In this manner a wellbore of substantially uniform diameter is obtained. Such procedure is particularly advantageous for relatively deep wellbores or for extended reach wellbores. Furthermore, it has been proposed to expand casings against the wellbore wall such that a seal is created between the casing and the wellbore wall without a cement layer inbetween. Although such expansion against the earth formation is considered feasible, there may still be concerns regarding the effectiveness of the seal after the casing has been expanded against the formation. Experience has indicated that cement may not be a good solution for sealing a very narrow annulus in view of the possibility that the cement does not adequately flow into the annular space, and in view of possible shrinkage of the (narrow) annular cement layer upon hardening.

It is therefore an object of the invention to provide an improved method of sealing an annular space formed between an expandable tubular element arranged in a wellbore and a wall surrounding the expandable tubular element, which overcomes the drawbacks of the prior art.

In accordance with the invention there is provided a method of sealing an annular space formed between an expandable tubular element arranged in a wellbore and a wall surrounding the expandable tubular element, whereby a pressure difference occurs between a first location in the annular space and a second location in the annular space axially spaced from the first location, the method comprising:

-   -   installing the tubular element in the wellbore;     -   locating a body of fluid in the annular space between said first         and second locations, said fluid having a yield strength         selected such that said pressure difference is insufficient to         induce axial flow of the body of non-hardening fluid in the         annular space after radial expansion of the tubular element; and     -   radially expanding the tubular element.

It is thereby achieved that the fluid can be inserted in the annular space at a relatively low pumping pressure prior to expansion of the tubular element, since the annular space is relatively wide before the expansion process. Once the fluid is in the annular space and the tubular element has been expanded, the pressure required to induce longitudinal movement of the body of fluid through the annular space, and thus the sealing capacity of the annular body of fluid, increases. Such increase is almost exponential if the annular space becomes very narrow such as in case the tubular element is expanded (almost) against the wellbore wall. It will therefore be understood that the method of the invention is particularly advantageous for applications whereby the tubular element is radially expanded to near the wellbore wall, or even locally against the wellbore wall.

Preferably said fluid is a non-hardening fluid, so that any risk of shrinkage of the annular body due to hardening is avoided.

A suitable fluid for use in the method of the invention is a thixotropic fluid. Preferably the fluid is selected from a gel, a Bingham Plastic and a Herschel Bulkley fluid.

Examples of suitable gels for use in the method of the invention are:

-   1) Chromium cross-linked Polyacrylamide such as Maraseal™, Marcit™     available from Schlumberger or OFPG. These gels are based on     partially hydrolyzed polyacrylamide polymers crosslinked with     Cr(III) released via a chrome acetate complex. Upper application     temperatures are 124° C. for Maraseal, and 104° C. for Marcit. After     setting, the gel is able to resist high concentrations of divalent     ions. -   2) Polyvinyl alcohol cross linked with a special (photosynthesized)     agent, such as disclosed by Advanced Gel Technology Inc. in US     2002/0128374A1, and named Wondergel™. For a more extensive     description of Wondergel™ reference is made to WO 03/083259, WO     04/041872, WO 98/12239, US 2004/0072946A1, US 2002/0128374A1 or GB     2396 617A1. -   3) Synthetic layered Silicate clay gels such as LAPONITE™. -   4) Thixotropic, oleophilic based clay packer gels for steam     injectors such as disclosed in U.S. Pat. No. 5,677,267. -   5) Oil based, thermal insulating gels such as disclosed in U.S. Pat.     No. 4,258,791 or U.S. Pat. No. 5,607,901 which are environmentally     safe, non aqueous, non corrosive and thermally insulating gels,     wherein the liquid part includes an ester of animal or vegetable     oil. -   6) In situ gelleable compositions, normally used in the shut-off of     steam injectors, for example as disclosed in U.S. Pat. No.     4,858,134. -   7) Thermoset synthetic gels having a long lifetime at elevated     temperature conditions, for example RTV Silicone gels such as Dow     Corning's Sylgard™ and/or perfluorether silicone gels such as Shin     Etsu's SIFEL™. -   8) Modified Xantham gums or HPG's for temperatures below 60° C. -   9) SilJel™, composed of inorganic silicates which solidify in     solution to form a permanent gel after a pre-determined set time.     The solution has a viscosity close to that of water until more than     90% of the set-time has elapsed. The set-time is temperature- and pH     dependent, and varies between a few minutes and a few hours at     temperatures up to 93° C., depending on the pH. The addition of urea     at higher temperatures results in a delayed gelling time due to the     buffering capacity of the urea through the formation of ammonia. -   10) Injectrol™, which is an internally catalyzed silicate system.     Three types of Injectrol™ systems are available dependent on the     catalyst applied, i.e. type G for temperatures between 23-66° C.,     type IT for temperatures between 49-82° C., and type U for     temperatures between 82-149° C. The internal catalyst system enables     pumping of a low viscosity solution (typically 1.2 mPa·s) into the     formation before the material sets to a stiff gel. The amount of     catalyst and the bottom hole temperature determines the gelling     time. For the type G system, the gelling time is between a few     minutes at 66° C. and 600 minutes at 23° C. -   11) H2zeroLT™ or H2zero™ developed by Halliburton, includes an     acrylamide acrylate co-polymer having a molecular weight of 250.000,     with polyethyleneimine as cross-linker. For applications at     temperatures below 50° C., ZrOCl₂ is used as cross-linker to achieve     reduced gelling times. -   12) PermSeal E+™ or PermSeal 600™, developed by Halliburton,     includes an acrylate monomer and a thermally controlled activator.     KCl, water and a pH adjuster (acetic acid) are included to provide a     standardized ionic concentration. Thermal degradation of the     activator induces in-situ polymerization of the polymer. Gelling     times can be controlled to be between 1 and 20 hours at temperatures     from 21 to 65° C. PermSeal initially has the same viscosity as     water, and forms a polymer after being pumped into the wellbore. -   13) Floperm 700™, developed by Halliburton, includes polyacrylamide     and phenol and formaldehyde as cross-linkers. Precursors which form     phenol and formaldehyde in-situ by degradation reactions, such as     hydroquinone and hexamethylenetetramine, are less toxic. Floperm     700™ can be used at temperatures up to about 175° C. The polymer     concentration is of the order of 3000-7000. -   14) HE300™, developed by Halliburton, includes three monomers     (acrylamide-based copolymers). This polymer is recommended for     temperatures beyond 100° C. Crosslinking is possible with organic     components, such as a mixture of phenol and formaldehyde or     precursors to phenol and formaldehyde. Resorcinol can be used to     accelerate the reaction at lower temperatures, while ferric ions can     delay the gelling process.

In order to enhance the sealing and/or plugging properties of the body of gel in the annular space, suitably the body of gel comprises a plurality of solid particles of large particle size distribution.

Suitable solid particles to be included in the body of fluid, are:

-   -   malleable particles such as walnut hulls, fibres (organic or         inorganic such as Nylon or Poly-ethylene), hollow ceramic         spheres, wood cuttings, and saw dust;     -   high density particles such as Mn3O4 (Micromax™), Barite,         Ilmenite, Haematite, Magnetite, Ferrosilicon, Specularite,         Ferrophosphorous, Silica flour, Silica sand, Bauxite particles,         Aluminium micro balls and micro steel balls;     -   low density particles such as fly ash, low density spheres (e.g.         Carboprop™), Bentonite, Pozzolanes, expanded Perlite, powdered         coal, Gilsonite™, glas and ceramic micro spheres;     -   poorly sorted particle systems such as Dense Crete™, Lite         Crete™, Sandaband™ and Silverfox™.

The invention will be described hereinafter by way of example in more detail, with reference to the accompanying drawings in which:

FIG. 1 schematically shows a wellbore provided with an expandable casing and a stream of gel being pumped into the wellbore;

FIG. 2 schematically shows the wellbore of FIG. 1 after pumping of the stream of gel into the wellbore;

FIG. 3 schematically shows the wellbore of FIG. 1 during radial expansion of the expandable casing;

FIG. 4 schematically shows the wellbore of FIG. 1 after radial expansion of the expandable casing; and

FIG. 5 schematically shows a diagram indicating the effect of radial expansion of a tubular element in a wellbore on the sealing functionality of a body of gel in the annular space between the tubular element and the wellbore wall.

In the drawings, like reference numerals relate to like components.

Referring to FIG. 1 there is shown a wellbore 1 formed in an earth formation 2 which includes a reservoir layer 3 containing hydrocarbon fluid, and an overburden layer 4 overlaying the reservoir layer 3. The wellbore 1 passes through the overburden layer 4 and extends into the reservoir layer 3. An expandable tubular element in the form of casing 6 extends from surface into the wellbore 1 such that the lower end of the casing 6 is arranged a short distance above the bottom 8 of the wellbore 1. An annular space 7 is formed between the casing 6 and the wellbore wall. A stream of gel 10 is pumped through the casing 6 and into the lower portion of the wellbore 1 using a pump plug 12 located in the casing 6. The pump plug 12 separates the stream of gel 10 from a suitable pumping fluid (such as brine) trailing the stream of gel 10 and the pump plug 12. The gel has a yield strength selected in accordance with selection criteria discussed hereinafter.

Referring to FIG. 2 there is shown the wellbore 1 after the stream of gel 10 has been fully pumped into the wellbore 1, whereby the pump plug 12 is located at the lower end of the casing 6. The gel 10 extends into the annular space 7 thereby forming an annular body of gel 11.

Referring to FIG. 3 there is shown the casing 6 during radial expansion thereof using an expansion cone 14 connected to a pump (not shown) at surface by a pipe string 16. The expansion cone 14 is operable between a collapsed state in which the cone 14 has a largest diameter smaller than the inner diameter of the unexpanded casing 6, and an expanded state in which the cone 14 has a largest diameter commensurate with the inner diameter to which the casing 6 is to be expanded. Further, the expansion cone is provided with a longitudinal through-passage 18 providing fluid communication between the interior of the casing 6 below the expansion cone 14, and the pipe string 16. A packer 20 is provided at the lower end of the casing 6. Similarly to the cone 14, the packer 20 is operable between a collapsed state in which the packer 20 has a largest diameter smaller than the inner diameter of the unexpanded casing 6, and an expanded state in which the packer 20 has a largest diameter commensurate with the inner diameter to which the casing 6 is to be expanded.

Referring to FIG. 4 there is shown the casing 6 after radial expansion thereof, whereby the expansion cone 14 and the plug 20 are removed from the casing 6, and whereby a production tubing 22 extends from surface through the expanded casing 6, and into the lower open-hole portion 13 of the wellbore 1. The production tubing 22 is at surface connected to conventional production equipment (not shown) so as to allow produced hydrocarbon fluid to flow from the lower open-hole portion 13 of the wellbore 1 to the production equipment. Further, the production tubing 22 is near its lower end sealed to the casing 6 by a production packer 24. The portion of the stream of gel 10 located in the lower open-hole portion 13 of the wellbore 1 has been removed from the wellbore 1.

During normal operation the casing 6 is lowered into the wellbore and suspended in the wellbore 1 from surface at the required depth. The annular space 7 is filled with brine (not shown). Subsequently the stream of gel 10 is pumped via the casing 6 into the wellbore 1 by means of the pump plug 12 which trails the stream of gel 10 in the casing (FIGS. 1 and 2). The stream of gel 10 flows into the annular space 7 thereby gradually displacing the brine present in the annular space 7.

Upon arrival of the pump plug 12 at the lower end of the casing 6, pumping is stopped and the pump plug 12 is removed from the casing 6 using a suitable retrieve string (not shown). At this stage the gel 10 fills the open-hole portion 13 of the wellbore 1 and extends into the annular space 7 thereby forming the annular body of gel 11.

In a next step the expansion cone 14 and the packer 20 are brought to their respective collapsed states, and the packer 20 is removably attached to the lower end of the cone 14. The combined cone 14 and packer 20 are then lowered through the casing 6 by means of pipe string 16 until the cone 14 extends below the lower end of the casing 6, i.e. in the open-hole portion 13 of the wellbore 1. The cone 14 is then brought to its expanded state and pulled into the casing 6 using a force multiplier (not shown) thereby radially expanding a lower end portion of the casing 6. When the cone 14 and the packer 20 are fully located in the casing 6, the packer 20 is radially expanded so as to be anchored to the inner surface of the casing 6. After the packer 20 has been set, the cone 14 is detached from the packer 20 and brine is pumped via the pipe string 16 and the through-passage 18, into the interior of the casing 6 between the cone 14 and the packer 20. The cone 14 thereby moves upwardly through the casing 6 and gradually expands the casing 6 (FIG. 3). As the annular space 7 becomes narrower during the expansion process, the annular body of gel 11 moves upwardly. Upward movement of the annular body of gel 11 stops when the expansion cone 14 arrives at a level where no gel is present anymore in the annular space 7. In the Figures, such level is indicated by dotted line A.

After the casing 6 has been fully expanded, or after expansion of a desired portion of the casing 6, the cone 14 and the packer 20 are removed from the casing. The open-hole portion 13 of the wellbore 1 is then cleaned, and the production tubing 22 and the production packer 24 are installed in conventional manner.

When the well is taken in production, hydrocarbon fluid flows from the reservoir zone 3 into the open-hole section 13 of the wellbore, and from there into the production tubing 22 to surface. The annular body of gel 11 seals the annular space 7 and thereby prevents that hydrocarbon fluid flows along the outside of the casing 6 in upward direction. In order that the body of gel 11 in the annular space 7 withstands the (high) fluid pressure of the hydrocarbon fluid entering the wellbore 1, the yield strength of the gel is selected such that the axial pressure difference across the body of gel 11 is lower than a minimum axial pressure difference across the body of gel 11 required to induce movement of the body of gel 11.

An example calculation of the minimum axial pressure difference across the annular body of gel required to induce movement of the body of gel for a given gel yield strength, is presented below.

EXAMPLE

A wellbore is drilled to a depth of 2000 m, with a diameter of 0.302 m (11.9 inch) in a lower section of the wellbore. The fluid pressure in the earth formation at the depth of 2000 m is 200 bar. An expandable casing is installed in the wellbore such that the lower end of the casing is positioned a short distance above the wellbore bottom. The outer diameter of the casing in unexpanded state is 0.244 m (9.625 inch). A stream of gel having a yield strength of 1000 Pa (0.01 bar), is pumped into the wellbore in the manner described above such that an annular body of gel of 2.28 m3 is contained in the annular space between the unexpanded casing and the wellbore wall. The length of the annular body of gel, before radial expansion of the casing, is 92.08 m. The maximum pressure at the lower end of the casing required to pump the gel in the annular space, is 63.74 bar which is well below the fracture pressure of the surrounding rock formation. The casing is then radially expanded to an outer diameter of 0.286 m (11.261 inch). The annular space thereby becomes narrower so that the length of the body of gel in the annular space increases to about 304.8 m (1000 ft). The effect of expansion of the casing on the minimum axial pressure required to induce longitudinal movement of the body of gel in the annular space, is twofold. Firstly the resistance of the body of gel to axial movement increases due to a longer contact surface with both the wellbore wall and the casing wall, and secondly the cross-sectional area of the annular body of gel decreases. In the present example it is found that the minimum axial pressure difference across the body of gel required to induce longitudinal movement of the body of gel through the annular space, increases from 211 bar before expansion of the casing, to 751 bar after expansion of the casing. In the present example, the axial formation fluid pressure difference across the body of gel is taken to be solely due to the hydrostatic column of formation fluid along the length of the body of gel, which is about 30 bar. Thus the actual axial fluid pressure difference across the body of gel is far below the minimum axial fluid pressure difference required to induce longitudinal movement of the body of gel. Therefore in the present example a gel with a lower yield strength could safely be applied if desired or, alternatively, the length of the body of gel in the annular space could be reduced.

Reference is further made to FIG. 5 showing a diagram illustrating the minimum axial pressure difference Pa (bar) required across an annular body of gel having a length of 10 m, to induce longitudinal movement of the body of gel through an annular space of width T (mm) for different magnitudes of the yield strength of the gel whereby:

-   -   line (a) indicates a gel yield strength of 50 Pa;     -   line (b) indicates a gel yield strength of 100 Pa;     -   line (c) indicates a gel yield strength of 200 Pa;     -   line (d) indicates a gel yield strength of 400 Pa;     -   line (e) indicates a gel yield strength of 800 Pa;     -   line (f) indicates a gel yield strength of 1600 Pa.         As apparent from the diagram, the magnitude of Pa increases         exponentially for T decreasing to near zero. The effect of         radial expansion of the tubular element is therefore that a gel         of relatively low yield strength can be used, or alternatively a         relatively short annular body of gel can be used, to achieve an         effective seal in the annular space. The sealing functionality         of the gel is particularly effective if the tubular element is         radially expanded to near the wellbore wall, or even locally         against the wellbore wall.

Instead of pumping a gel into the wellbore, a fluid can be pumped which transforms into a gel some time after being pumped into the wellbore. Thus, such fluid obtains the desired yield strength and, optionally, the desired thixotropic properties after being inserted in the wellbore. 

1. A method of sealing an annular space formed between an expandable tubular element arranged in a wellbore having a wellbore wall and a wall surrounding the expandable tubular element, whereby a pressure difference occurs between a first location in the annular space and a second location in the annular space axially spaced from the first location, the method comprising: installing the tubular element in the wellbore; locating a body of fluid in the annular space between said first and second locations, said fluid having a yield strength selected such that said pressure difference is insufficient to induce axial flow of the body of fluid in the annular space after radial expansion of the tubular element; and radially expanding the tubular element.
 2. The method of claim 1, wherein said body of fluid is at least partly located in the annular space by pumping said fluid via the tubular element before expansion thereof, into the annular space.
 3. The method of claim 1, wherein said body of fluid is at least partly located in the annular space by the step of radially expanding the tubular element.
 4. The method of claim 1, wherein said wall is the wellbore wall.
 5. The method of claim 1, any one of claims 1, wherein said fluid is a non-hardening fluid.
 6. The method of claim 1, wherein said fluid is a thixotropic fluid.
 7. The method of claim 1, wherein said fluid is selected from the group consisting of a Bingham Plastic and a Herschel Bulkley fluid.
 8. The method of claim 1, wherein said fluid is a gel.
 9. The method of claim 8, wherein the gel comprises at least one of a chromium cross-linked polyacrylamide, a polymer cross-linked by a backbone of carbon atoms, a synthetic layered silicate clay, an oleophilic based clay packer gel, an oil based thermal insulating gel, an in situ gelleable composition, a thermoset synthetic gel, and a modified xantham gum.
 10. The method of claim 9, wherein the gel comprises a polymer cross-linked by a backbone of carbon atoms, and wherein said backbone of carbon atoms comprises groups capable of forming bonds with the polymers.
 11. (canceled)
 12. The method of claim 8, wherein the gel comprises a chromium cross-linked polyacrylamide which is partially based on hydrolyzed polyacrylamide polymers cross-linked with Cr (III).
 13. The method of claim 8, wherein the gel comprises a synthetic layered silicate clay.
 14. The method of claim 8, wherein the gel comprises a thermoset synthetic gel comprising at least one of a RTV silicone gel or a perfluorether silicone gel.
 15. (canceled)
 16. (canceled)
 17. The method of claim 8, wherein the stream of gel comprises a plurality of solid particles of different sizes.
 18. (canceled) 